Knowing the properties and locations of underground rock formations is useful for making decisions as to where and how to economically produce hydrocarbons from the subsurface. In particular, an asset team making development and production decisions may encounter various rock types in an underground formation, where each rock type may be comprised of petrophysical and hydraulic rock properties describing composition, structure, and multiphase fluid flow characteristics. For example, a section of an underground formation may be comprised of the following different rock types: sandstone; carbonate; and shale, where each rock type has rock properties that differ from one another and vary within each classification.
In order to ascertain information regarding the underground reservoir formation, rock properties for each rock type of the formation may be measured and subsequently recorded in a well log. Well logging is a technique used to identify properties associated with earth formations immediately surrounding a wellbore. The interrogation of a formation surrounding a wellbore to identify one or more property of a rock type may be by, for example, sound, electrical current, electromagnetic waves, or high energy nuclear particles (e.g., gamma particles and neutrons). A geologist can use the aggregated rock properties within a well log to make a determination of geologic rock types surrounding the associated well. This information can then be used to generate static three-dimensional (3D) geocellular models of the underground formation. The simulation of fluid flow dynamically within the geocellular model by a reservoir engineer requires a description of hydraulic conductivity for each modeled rock type in order to properly depict rock-fluid interaction in the dynamic model. Rock-fluid interaction is typically measured as multiphase relative permeability using core samples obtained from the wellbore that are representative of the drilled formation. The coupling of static model construction and dynamic modeling then allows the assessment of a formation's potential for production of hydrocarbon deposits, such as oil and natural gas.
As rock properties are measured only within a limited radius around the well in which measurements are taken, the determination as to the rock type may apply to only a small portion of the underground formation within a limited distance from the well (based on the measurements obtained from the well logs). Consequently, a 3D model of the underground formation as a whole may require the rock type determined for one portion of the formation to be applied to other portions for which measurements were not taken, e.g., portions of the formation located between a well and a nearby offset well, as if the rock type were a regionalized variable.
For a more accurate distribution of rock types in the 3D model of the formation, the geologist or reservoir engineer may define petrofacies as different regions of the 3D model according to specified ranges of selected petrophysical properties (e.g., porosity and absolute permeability). Hydraulic rock type properties, such as relative permeability and capillary pressure, may be assigned to relevant portions of the 3D model according to the defined petrofacies. The petrofacies definitions may be validated against previously derived seismic attribute data (typically in the form of acoustic impedance). However, such conventional techniques for defining petrofacies based on specified petrophysical property ranges presuppose that the relationships between petrophysical properties are defined by rigid rock property cutoffs and/or that linear petrofacies relationships are to be enforced. As the hydraulic rock type properties of the actual formation generally are not distributed according to such linear petrofacies relationships, the resulting 3D model may not provide an accurate representation of the fluid flow characteristics and heterogeneity of the formation being modeled.